Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geological formation by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbon to reach the surface. In order for the hydrocarbon to be “produced,” that is, travel from the formation to the wellbore and ultimately to the surface, there must be a sufficiently unimpeded flow path.
Hydraulic fracturing is a primary tool for improving well productivity by placing or extending highly conductive fractures from the wellbore into the reservoir. During the first stage, hydraulic fracturing fluid is injected through wellbore into a subterranean formation at high rates and pressures. The fracturing fluid injection rate exceeds the filtration rate into the formation producing increasing hydraulic pressure at the formation face. When the pressure exceeds a critical value, the formation strata or rock cracks and fractures. The formation fracture is more permeable than the formation porosity.
During the next stage, proppant is deposited in the fracture to prevent it from closing after injection stops. The resulting propped fracture enables improved flow of the recoverable fluid, i.e., oil, gas or water. Sand, gravel, glass beads, walnut shells, ceramic particles, sintered bauxites and other materials may be used as a proppant.
Hydraulic fracturing fluids are aqueous solutions containing a thickener, such as a solvatable polysaccharide, to provide sufficient viscosity to transport the proppant. Typical thickeners are polymers, such as guar (phytogeneous polysaccharide), and guar derivatives (hydroxypropyl guar, carboxymethylhydroxypropyl guar). Other polymers can be used also as thickeners. Water with guar represents a linear gel with a viscosity proportional to the polymer concentration. Cross-linking agents are used which provide engagement between polymer chains to form sufficiently strong couplings that increase the gel viscosity and create visco-elasticity. Common crosslinking agents for guar include boron, titanium, zirconium, and aluminum.
Proppant-retention agents are commonly used during the latter stages of the hydraulic fracturing treatment to limit the flowback of proppant placed into the formation. For instance, the proppant may be coated with a curable resin activated under downhole conditions. Different materials, such as bundles of fibers, or fibrous or deformable materials, also have been used to retain proppants in the fracture. Presumably, fibers form a three-dimensional network in the proppant, reinforcing it and limiting its flowback.
The success of a hydraulic fracturing treatment depends upon hydraulic fracture conductivity and fracture length. Fracture conductivity is the product of proppant permeability and fracture width; units are typically expressed as millidarcy-feet. Fracture conductivity is affected by a number of known parameters. Proppant particle size distribution is one key parameter that influences fracture permeability. The concentration of proppant between the fracture faces is another (expressed in pounds of proppant per square foot of fracture surface) and influences the fracture width. One may consider high-strength proppants, fluids with excellent proppant transport characteristics (ability to minimize gravity-driven settling within the fracture itself), high-proppant concentrations, or big proppants as means to improve fracture conductivity. Weak materials, poor proppant transport, and narrow fractures all lead to poor well productivity. Relatively inexpensive materials of little strength, such as sand, are used for hydraulic fracturing of formations with small internal stresses. Materials of greater cost, such as ceramics, bauxites and others, are used in formations with higher internal stresses. Chemical interaction between produced fluids and proppants may change significantly the proppant's characteristics. One should also consider the proppant's long-term ability to resist crushing.
The proppant pack must create a layer having a higher hydraulic conductivity than the surrounding formation rock. The proppant pack within the fracture can be modeled as a permeable porous structure, and the flow of formation fluids through this layer is generally described using the well-known Darcy's law (1) or Forscheimer's equation (2):∂P/∂x=−(μu/k);  1∂P∂x=−[(μu/k)+βρu2],  2
where P is a fluid pressure in the fracture;                x is a distance along the fracture from the wellbore;        μ is a viscosity of the formation fluid;        u is a flow (filtration) speed of the formation fluid;        k is a permeability of the proppant pack;        β is a coefficient referred to as beta-factor that describes non-linear corrections to the Darcy's filtration law;        ρ is a density of the formation fluid.        
The result of multiplying fracture permeability by fracture width is referred to as hydraulic conductivity. An important aspect of fracture design is optimization of the hydraulic conductivity for a particular formation's conditions. Fracture design theory and methodology are sufficiently well described in several scientific articles and monographs. Reservoir Stimulation, 3rd ed. Economides, Michael J. and Nolte, Kenneth G., John Wiley and Sons (1999) is a good example of a reference that provides good fracture design methodology.
A fracture optimization process will strike a balance among the proppant strength, hydraulic fracture conductivity, proppant distribution, cost of materials, and the cost of executing a hydraulic fracturing treatment in a specific reservoir. The case of big proppants illustrates compromises made during an optimization process. A significant hydraulic fracture conductivity increase is possible using large diameter proppants. However, large diameter proppants at a given internal formation stress crush to a greater extent when subjected to high fracture closure stresses, leading to a decrease in the effective hydraulic conductivity of the proppant pack. Further, the larger the proppant particles, the more they are subjected to bridging and trapping in the fracture near the injection point.
A particular proppant is selected based on its ability to resist crushing and provide sufficient fracture conductivity upon being subjected to the fracture closure stress; and its ability to flow deeply into the hydraulic fracture—cost effectively. Proppants are second after water according to volume and mass used during the hydraulic fracturing process. Ceramic proppant has superior beta-factors and more strength compared to sand. However, the cost of ceramic proppants is many fold higher than the cost of sand. Therefore, fracture conductivity improvement requires significant costs for hydraulic fracturing with proppant typically representing 20 to 60 percent of the total for a conventional hydraulic fracturing process.
Apart from the above considerations, there are other proppant characteristics that complicate the production of hydrocarbons. First, formation fluids often bypass a large fraction of the fluid used in the treatment. (The fluid remaining in the proppant pack damages the conductivity of the fracture.) Field studies have shown that the recovery of hydraulic fracturing fluid from fractures in natural gas wells averages only 20 to 50 percent of that injected during the treatments and can be much less. Probably formation fluids flow only along several channels in the form of “fingers” within the proppant pack, or only through that part of the proppant pack near the wellbore during the fracture clean-up process. The fracture portion containing residual viscous gel hinders fluid flow, thereby reducing effective hydraulic fracture conductivity. Lowering the fracturing fluid viscosity after the treatment is an effective way to increase the fracturing fluid recovery from the proppant pack porosity. The addition of substances called “breakers” promotes gel viscosity reduction. Breakers act by several mechanisms, but most commonly they function by cleaving polymer chains to decrease their length and, thereby, to reduce the polymer solution viscosity. Different breakers are characterized by such parameters as the rate of reaction between the breaker and the polymer, and the activation or deactivation temperatures of the specific breaker in question. Better fracture cleanup can be achieved using high breaker concentrations, but too high a breaker concentration can result in a premature gel viscosity reduction, which may compromise the treatment design and cause premature treatment completion—a screen out. Delayed action breakers, such as encapsulated, were developed to solve this problem. Encapsulated breakers are active breaker chemicals, such as oxidizer granules, coated by protective shells, which isolate the oxidizer from the polymer and delay their reaction. Shell destruction and breaker release take place through various mechanisms, including the action of mechanical stresses occurring at fracture closure. Encapsulated breakers enable higher breaker concentrations to be used in the hydraulic fracturing fluid and, therefore, increase the extent of fracture cleaning.
Another factor reducing fracture conductivity is pore clogging in the proppant pack by formation particles formed during the fracturing process, by proppant particles formed by proppant crushing; and by immiscible fluids (The Impact of Non-Darcy Flow on Production from Hydraulically Fractured Gas Wells, SPE Production and Operations Symposium, 24-27 March, Oklahoma City, Okla., 2001; A Study of Two-Phase, Non-Darcy Gas Flow Through Proppant Packs, SPE Production & Facilities, Volume 15, Number 4, November, 2000). So, evidently, a fracture in which formation fluids flow through a created channel network instead of through small pores in the proppant pack could improve the fracture's hydraulic conductivity by several mechanisms: reduced inertial losses, improved fracturing fluid clean up, reduction of capillary forces that impose significant two-phase flow pressure losses, and elimination of pore throat plugging by the capture of formation fines and crushed proppant fragments.
In recent years, fracturing treatments in many low permeability formations in North America were pumped using low viscosity hydraulic fracture fluids that were proppant-free or with only a small amount of proppant. This method has several names, the most common of which is referred to as a waterfrac. Fractures created by the waterfrac process are practically proppant-free. It is anticipated that the created fracture surfaces shift relative to each other during fracture creation and propagation. The resulting misalignment of irregular surface features (asperities) prevents the two fracture faces from forming a tight seal upon closure. Adding a small amount of proppant reportedly intensifies the effect of irregular and misaligned crack surfaces. However, due to poor transport, the proppant tends to accumulate below the casing perforations, most likely along the base of the created hydraulic fracture. This accumulation occurs due to a high rate of proppant settling in the fracturing fluid along a narrow hydraulic fracture, and insufficient proppant transport ability, (both because of low fracturing fluid viscosity). When fracturing fluid injection stops at the end of a waterfrac, the fracture immediately shortens in length and height. This slightly compacts the proppant, which remains as a “dune” at the fracture base near the wellbore. Because of the dune's limited length, width and, typically, strength (often low-strength sand is used), waterfracs are usually characterized by short, low-conductivity fractures (Experimental Study of Hydraulic Fracture Conductivity Demonstrates the Benefits of Using Proppants, SPE Rocky Mountain Regional/Low-Permeability Reservoirs Symposium and Exhibition, 12-15 March, Denver, Colo., 2000).
The previous discussion illustrates that waterfracs result from the passage of formation fluid flowing through the network of narrow channels created inside of the fracture due to incomplete closure caused by surface rock imperfections, i.e. the waterfrac process results in low conductivity fractures. One method of improving hydraulic fracture conductivity is to construct proppant clusters in the fracture, as opposed constructing a continuous proppant pack. U.S. Pat. No. 6,776,235 discloses a method for hydraulically fracturing a subterranean formation involving an initial stage of injecting hydraulic fracturing fluid into a borehole, the fluid containing thickeners to create a fracture in the formation; and alternating stages of periodically introducing into the borehole proppant-containing hydraulic fracturing fluids contrasting in their abilities to transport propping agents and, therefore, contrasting in proppant-settling rates to form proppant clusters as posts that prevent fracture closing. This method alternates the stages of proppant-laden and proppant-free fracturing fluids. The amount of proppant deposited in the fracture during each stage is modulated by varying the fluid transport characteristics (such as viscosity and elasticity), the proppant densities, diameters, and concentrations and the fracturing fluid injection rate.
Periodic injection of the proppant used in the present method involves transportation of each portion of proppant, first, down through the well; then, through perforations of the casing string into a fracture; and, further, through the fracture along its length. Since proppant-containing and proppant-free fracturing fluids have different specific gravities, the proppant-containing fluid can settle, or underride, the proppant-free fluid. Such settling results in non-uniform distribution of proppant clusters in the fracture.